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Abstract This paper presents the theory and formulation of the compressibility, porosity, and permeability of shale reservoirs by considering the effects of stress shock causing slope discontinuity and loading/unloading hysteresis. The slope discontinuity happens because the relative contributions of the matrix and fracture change at a critical effective stress at which the fractures close or open depending on whether the process is loading or unloading. The hysteresis phenomenon occurs as a result of partially reversible and irreversible deformations of the various shale rock constituents by various processes during loading and unloading. Two semi-analytical modeling approaches are developed for describing the stress-dependency of the petrophysical properties of porous rock formations. The first approach implements a kinetic model and the second approach applies an elastic cylindrical pore-shell model. Both approaches yield high-quality correlations of the various petrophysical properties of porous rocks with effective stress by honoring the slope discontinuity observed in the compressibility, porosity, and permeability of rocks at critical effective stress. Introduction Shale rock formations include matters of inorganic (quartz, clay, etc.) and organic (kerogen) in the rock matrix, gas at various states (dissolved, adsorbed, and free gases), and brine (water and dissolved salts). The pore system in naturally fractured rocks contains both the matrix and fracture porosity. Some induced fractures are generated in brittle rocks during stress deformation and hydraulic fracturing. The contribution of the interconnectivity of pores and the porosity in the inorganic and organic matters, and the fracture system to the overall effective porosity and permeability of shale rocks depends on the effective stress. The effective stress ฯ acting upon porous rocks is determined by an amended Biot's (1941) law as the difference between the total confining stress ฯc and some degree of participation of the pore fluid pressure p (Biot and Willis, 1957; Kรผmpel, 1991, Kwon et al., 2001, Walls and Nur, 1979, Zimmermann, 1991, Zoback and Byerlee, 1975a, b): (equation) (1)
- North America > United States > Oklahoma (0.46)
- North America > United States > California (0.46)
- North America > United States > Texas > Harris County > Houston (0.28)
- North America > United States > Kentucky > Illinois Basin (0.99)
- North America > United States > Indiana > Illinois Basin (0.99)
- North America > United States > Illinois > Illinois Basin (0.99)
- Asia > China > Sichuan > Sichuan Basin (0.99)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
Summary Engineering and economic optimization of the value of water as an essential commodity and successful management of the overall water cycle are of great interests for the petroleum industry. The general objective is to maximize the benefits and safety in the utilization of water during the oil and gas production operations including for shale reservoirs while minimizing the environmental impact and the cost of operations. Accomplishing this objective requires scientifically guided and engineering prudent approaches. This paper provides a comprehensive overview of the various issues of critical importance in optimal management of the water cycle in the oil and gas fields. The present general discussion focuses on a review and an integrated analysis of the water resources, considering the issues of availability, characterization, production, processing, transportation, storage, disposal, reinjection, and utilization for production from the hydrocarbon-bearing reservoirs with their associated energy involvement and environmental safety requirements. Introduction Exploring the most engineering, economic, and environmentally effective strategies for beneficial utilization of field water resources and optimization of the water cycle in reservoir operations and petroleum production systems requires a comprehensive understanding of the overall field water resources and issues of relevance for proper characterization and processing of water. This paper provides a concise and complete review of the water handling issues of practical importance by including some highlights from the available literature and the previous invited presentations of the author (Civan, 2012, 2013, 2014a, b). An overview of the technical and environmental issues of practical importance in dealing with balancing between the various water resources, water utilization options, regulations and measures, and efforts for informing and educating the public is provided in a concise manner. Water involving the petroleum field operations is examined in two categories: Natural water sources (availability, accessibility, aquifer, ground, sea, compatibility, and injectivity) and wastewater (generation, quality, quantity, and composition in drilling, completion, and production). Water processing issues are reviewed in terms of three aspects: Water characterization (present and required quality), treatment methods (in-situ and surface, parameters, quality, capacity, separated materials and sludge), and equipment (gas/liquid/particulate separation, storage, transportation, and measurement).
- Europe (1.00)
- Asia > Middle East (0.94)
- North America > United States > Oklahoma (0.46)
- North America > United States > Texas > Coleman County (0.24)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.50)
- Geology > Structural Geology > Tectonics > Plate Tectonics > Earthquake (0.47)
Summary Transport of gas in extremely-low permeability shale-gas reservoirs involves complex processes of absorption, adsorption, and pore-confinement effect in nanopores; significant deviations occur from Darcy-type flow; and gas properties such as real gas deviation factor and viscosity are significantly altered compared to conventional reservoir conditions. This paper presents a physically rigorous modeling of shale gas transport by considering the various effects of importance in nanopores to derive the proper equations of gas storage and transport, and to demonstrate various applications of practical interest. First, previous approaches are critically reviewed to delineate their outstanding features and shortcomings. Then, a non-Darcy gas transfer equation, comprehensive gas storage model, and quantification of the relevant parameters including permeability are developed. Next, the improved model is used to simulate gas transport in laboratory tests conducted under near-real shale-gas reservoir conditions. Improved non-Darcy nanopore gas storage and flow model describes the shale gas transport properly and can be used satisfactorily in shale-gas reservoir simulation. 1 Introduction Although the theory of gas transport through extremely narrow flow paths in porous media have been reasonably well established, the analyses of experimental data have not been quite successful judging by the results reported in the literature. For example, Javadpour (2009) had to adjust the values of three empirical parameters to be able to achieve a matching of experimental data. Darabi et al. (2012) applied the apparent permeability function (APF) concept which was originally formulated by Ertekin et al. (1986). Darabi et al. (2012) also have three adjustable parameters. Unique determination of these three adjustable parameter values is questionable. Because of the error as pointed out in this paper, the model given by Javadpour (2009) did not match the measured data. The simulation results presented by Roy et al. (2003) and Veltzke and Thรถming (2012) also deviate significantly from their own experimental data. These papers attempted to determine the values of their adjustable parameters using only one set of experimental data. Civan et al. (2012) explained that "one must run a minimum number of tests that is more than the number of adjustable parameters with the same system but conducted under different conditions to achieve uniqueness."
- North America > United States > Texas (0.28)
- North America > United States > Oklahoma (0.28)
Summary Determination of the nanodarcy gas permeability and other parameters of naturally and hydraulically fractured shale formations by pressure-pulse transmission testing of core plugs, drill cuttings, and crushed samples is discussed. The methods available for interpretation of pressure tests are reviewed and modified with emphasis on difference between the intrinsic and apparent permeability. Improved formulations and analysis methods which honor the relevant physics of fluid and transport, and interactions with shale are presented. Better design and analysis of experiments for simultaneous determination of several unknown parameters that impact the transport calculations, including deformation, adsorption, diffusion, and deviation from Darcy flow are described. The permeability and other parameters of shale samples are recommended to be determined by simultaneous analysis of multiple pressure tests conducted under different conditions to accommodate for temporally and spatially variable conditions. The inherent limitations of the methods relying on the analytical solutions of the diffusivity equation based on the Darcy's law are explained. Introduction The permeability measured using a Darcy-like equation is not the intrinsic permeability but the apparent permeability which depends on the prevailing conditions of fluid, transport, and shale. The intrinsic permeability of shale depends on the temperature and effective stress conditions and therefore the conditions of a particular intrinsic value should also be specified. The primary reason for the contradictory values of permeability measured by application of the analytical models is explained by dependence of measured permeability of shale on particular testing conditions over which only a certain average permeability value is obtained from most analytical solutions. Crushed samples have different size particles. The permeability of a particle depends on its size. Large particles are likely to have both the matrix porosity and fracture porosity. Consequently, it is not correct to assume all the particles of different sizes to have the same permeability. Whereas, most attempts in calculating the permeability using the pressure tests on crushed samples assume the same permeability for all particles. This assumption can only be applicable for samples of uninform particle sizes.
- North America > United States > Texas (1.00)
- Europe (0.68)
Summary This paper proposes that the crushed-sample permeability can match the core plug permeability measurements when tests are repeated with sufficient number of different mesh size crushed samples instead of relying on a single mesh size sample testing and then extrapolating the results to the representative bulk volume size of shale formations. The formulations necessary for this approach are developed by considering the averaging of the matrix and fracture porosities over the crushed sample particle volumes and the non-Darcy behavior and adsorption of real gasses under the pore-proximity effects.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.96)
Abstract The modeling and simulation of commingled production from multilayered shale-gas reservoirs is presented and the changing pressures and flow rates in various zones are simulated. An effective iterative numerical simulation is developed for the coupled wellbore and reservoir hydraulics calculations for multi-layered shale gas reservoirs. The performance of each layer communucating with the wellbore, in the absence or presence of formation cross flow, is evaluated and demonstrated by case studies. Changes in the permeability of shale with prevailing conditions is accounted for by considering the apparent gas permeability in shale depending on the pore proximity effects. This rigorous simulation method presented here enables an accurate evaluation of the pressure and production at each layer including the cross flow effects. Introduction Commingled production from wells completed in multi-layered reservoirs commonly exist in many fields, including the shale-gas reservoirs. Such reservoirs performance is usually monitored by means of the logging tools to obtain the downhole pressure and production measurements of different layers. Frequently, the temperature and noise logs are used to detect the wellbore crossflow, but no effective tool is available for measurement of the formation cross-flow. Direct measurements usually require expensive and time-consuming approaches and interruption of production wells. Prediction of the flow rate and pressure profiles at separate zones and the contribution of each zone to overall well production is required for management of production from commingled reservoirs. The problem is more complicated when formation cross flow occurs between varios zones and because of permeability effects created in layers separating the pay zones by induced fractures resulting from stress deformation and other means. Stratified shale layers may also have different fluid and formation properties depending of their own sedimentary deposition processes and may involve different types of external boundary conditions, including full or partial water influx. Therefore, various stratified layers can have different contributions on well production performance, and well optimization and management. A rigorous phenomenological modeling is therefore required to rigorously quantify the contribution of each layer to the overall production and analyze the effect of cross flow for commingled shale gas reservoirs. Juell et al. (2011) used a backpressure equation to estimate the gas properties of multi-layer reservoir including wellbore crossflow. They assumed the well was produced at a constant bottom-hole flowing pressure. They compared the reservoir backpressure calculation and the results from the numerical simulator, and concluded that the backpressure equation can be used to predict the performance of layered reservoirs when coupled with material balance equation in the case of no-crossflow gas reservoirs. Also, solution of reservoir backpressure equation against reservoir material balance equation solution has been verified. URTeC 1582508
Critical Evaluation of Equations of State for Multicomponent Hydrocarbon Fluids in Organic Rich Shale Reservoirs
Zhang, Yijia ( University of Oklahoma) | Civan, Faruk (University of Oklahoma) | Devegowda, Deepak (University of Oklahoma) | Jamili, Ahmad (University of Oklahoma) | Sigal, Richard F. (Consultant)
Abstract The various equations of state and modifications proposed for use in nanoporous systems are critically examined. The fluid properties modifications in nanoporous systems produced by the effect of pore wall potentials and the limited number of molecules in nanopores are investigated for liquid-rich shale. These properties include phase behavior, interfacial properties, gas and liquid transport, storage, and composition. The existing theoretical equations are modified to predict the vapor-liquid equilibrium for shale and the unique behavior of fluids in kerogen and inorganic pores. The pore geometry, molecule size, interaction between the sorbed molecules and the nanoporous framework are included to enable accurate prediction of fluid phase behavior, critical properties, and composition. The predictions of the proposed approaches are compared to results obtained from molecular dynamic simulations. Introduction The study of fluid properties in nanoporous systems continues to receive considerable attention because of the shift towards the development of liquid-rich shale plays. In these nanoporous shales, it is now increasingly recognized that pore-wall proximity determines to a large extent the fluid phase behavior, its interfacial properties, gas and liquid transport, storage, and composition. We focus on a comprehensive and critical evaluation of existing equations-of-states (EOS) to quantify vapor-liquid equilibrium for shales and review the need for modified EOS's in order to address the unique behavior of fluids in kerogen and inorganic pores. Several factors that need to be considered are the pore geometry, molecule sizes, interaction between the sorbed molecules and the nanoporous framework. Proper consideration of these factors will enable more accurate prediction of fluid phase behavior, its critical properties, and composition which will lead to improved forecasting and reserves estimation. We review the limitations in the applicability of existing EOS for multicomponent, multiphase fluid description in shale nanopores. A comparison is made of the predictive capability of these equations against results obtained from pore scale molecular dynamic simulations describing fluid phase behavior in nanopores. We then review the modifications to these equations of states proposed to capture pore wall proximity effects and explore the validity of these for compositional shale gas simulation. Finally, we propose convenient modifications to existing EOS that quantifies fluid phase and compositional behavior across a wide range of pore sizes and pore pressures in adsorbing and non-adsorbing walls. The approach to modification of equations-of-state outlined in our work enables improved reservoir performance forecasting, reserves estimation, calculations of condensate dropout and additionally, enables operators to characterize the original in-situ fluid composition from the produced gas and liquid streams. URTeC 1581765
A Pore Scale Study of Slickwater Systems in Shale Reservoirs: Implications for Frac-Water Distribution and Produced Water Salinity
Hu, Yinan (University of Oklahoma) | Devegowda, Deepak (University of Oklahoma) | Striolo, Alberto (University of Oklahoma) | Phan, Anh (University of Oklahoma) | Ho, Tuan A. (University of Oklahoma) | Civan, Faruk (University of Oklahoma) | Sigal, Richard (Consultant )
Abstract Pore-level molecular dynamics simulation studies are conducted towards an understanding of poor recovery of frac-water, progressive increase in produced water salinity, and identification of potential trapping mechanisms for frac-water and its influence on long-term well productivity in shale gas and oil reservoirs. The kerogen pores of shales are represented by two organic pore models. The first model containing only carbon is intended to mimic the nature of highly mature kerogen. The second model helps understanding of the fluid behavior in partially mature shales containining oxygenated functional groups with non-zero oxygen to carbon ratio. The maturation processes of these kerogen models are described by means of a molecular dynamics simulation. These models are shown to describe effectively the essential structural features observed in SEM images which indicate surface roughness, tortuous paths, material disorders, and imperfect pore openings of kerogen pores, and are therefore superior to the frequently assumed graphene slit pore systems. The effect of maturation, pore surface mineralogy, and pore roughness on the wettability characteristics of organic kerogen pores is delineated. Distribution of saline water in organic and inorganic pores is described as a function of pore size and morphology. These pore-scale studies reveal important insights about the distribution of dissolved ions and water in organic pores, and the frac-water distribution and produced water salinity following hydraulic fracturing. Introduction Shale gas and oil development activities have continually undergone several stages of refinement and continues to be driven by our ability to create extensive multi-stage hydraulic fracture treatments along several thousands of feet of horizontal laterals. Although these efforts have largely progressed successfully, unfortunately, our current understanding of the complex interplay of hydrocarbons and water in organic and inorganic shale nanopores is rather limited. Among the key questions remaining unanswered are related to the explanation of the poor recovery of frac-water, the progressive increase in produced water salinity, and the potential trapping mechanisms for frac-water and its influence on long-term well productivity. URTeC 1579803
- North America > United States > Texas (0.68)
- North America > United States > Oklahoma > Cleveland County > Norman (0.15)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type (1.00)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (11 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)